A major concern with the utilization of certain fuels in directly fired conventional power generation systems and other processes is the particulates produced by combustion of the fuels. These particulates remain in the combustion gas stream. Because the gas stream running such systems can adversely impact on the life of the equipment, the gas stream should be substantially free of the particulate matter. Although conventional particulate removal devices may be used to remove some of the larger solid particulate matter from combustion gas streams, these devices generally fail to remove the smaller particulates from the streams. Similar problems also exist in many gas streams in which the particulate suspended matter originates from other than combustion.
U.S. Pat. No. 5,353,721 to Mansour, et al. and U.S. Pat. No. 5,197,399 to Mansour, et al., which are incorporated herein in their entirety by reference thereto for all purposes, describe a pulsed combustion apparatus and process for acoustically agglomerating particulates produced by the combustion of fuels so that the particulates may be removed from the combustion effluent stream. Once the particles are removed from the combustion effluent stream, the stream can then be used in various processes and systems. For example, in one embodiment, the effluent stream can be used to rotate a turbine for producing electricity.
Tests conducted in this mode in a process development unit (PDU) with pulverized bituminous coal and four different sorbents for sulfur capture provided the following results: (1) the combustion efficiency exceeded 99 percent; (2) sulfur capture was as high as 98 percent; (3) NOx emissions were in the range of 0.3 to 0.6 lb/MMBtu; and (4) the solids loading in cyclone exit flue gas (analogous to turbine inlet solids loading) was as low as 23 ppmw. The solids loading result greatly surpassed the original target goal of 100 to 150 ppmw and was good enough to meet the New Source Performance Standards (NSPS) for particulate emissions from power plants ( less than 0.03 lb/MMBtu).
However, while the operation in the combustion or fuel lean mode provided satisfactory and encouraging results, the process was constrained thermodynamically and presented various problems related to emissions control. Specifically, the following limitations became apparent:
Sulfur retention or calcium utilization decreases with an increase in operating temperature under oxidizing or fuel lean conditions. For example, the Ca/S molar feed ratio required for 95% sulfur capture is very favorable at temperatures up to about 1,000xc2x0 C. (1,832xc2x0 F.) but rises sharply with further increase in temperature. This constrains the gas turbine inlet temperature and in turn the cycle or plant efficiency.
Although pulse combustors are inherently low NOx devices, oxidizing mode of operation, presence of fuel bound nitrogen and high temperature all favor NOx formation. Therefore, further NOx reduction, especially in the context of rising gas turbine inlet temperature requirement, was needed.
Higher temperatures ( greater than 1,000xc2x0 C. or 1,832xc2x0 F. ) in the agglomeration chamber favor acoustic agglomeration, but not sulfur capture. This tends to limit the extent of decrease in the solids loading in cyclone exit flue gas.
As such, a need currently exists for an improved agglomeration apparatus and process.
In accordance with one embodiment of the present invention, an apparatus and process for gasification of feedstocks (e.g., coal, coke, other solid fuels, heavy liquid hydrocarbons, slurries, and the like) with in-situ hot gas clean-up to generate clean, medium Btu gas is disclosed. In one particular embodiment, the process employs a pulsed gasification device that incorporates one or two stages of gasification. The process promotes acoustic agglomeration of particulates to aid in particulate collection using conventional separation apparatus, and facilitates the use of appropriate sorbents to capture gaseous pollutants in a sonic-enhanced environment. The apparatus may be employed in a variety of different configurations, such as combined cycle configurations with varying combinations of fuel cell, gas turbine and steam turbine for power generation, as well as in cogeneration configurations for combined heat and power production, for hydrogen production, for liquid fuels production, or for direct reduction of iron.
In one embodiment, for instance, the gasifier system includes a pulse combustion device for first-stage gasification, a U-tube arrangement for slag removal, a vertical entrained flow section for second-stage gasification, and primary and secondary cyclones for particulate capture. Oxygen and steam can be used as gasification agents to enhance the product gas heating value and, in turn, promote flame stability and turndown partial oxidation. For instance, partial oxidation can occur in the first stage while predominantly steam reforming processes can occur in the second stage.
In the second stage, sorbent particles are injected into a gas stream subjected to an intense acoustic field. The acoustic field serves to improve sorbent calcination by enhancing both gas film and intra-particle mass transfer rates. In addition, the sorbent particles act as dynamic filter foci, providing a high density of stagnant agglomerating centers for trapping finer entrained flyash fractions. A regenerate sorbent can be used for in-situ sulfur capture and a sulfur recovery unit may be included to generate a sulfur byproduct. The byproduct can be, for instance, ammonium sulfate or elemental sulfur or sulfuric acid.
In one particular embodiment, the system of the present invention is for producing a gas stream having fuel or heat value. The system can include a fluid channel including a first stage section and a second stage section. The fluid channel may include a U-shaped section that transitions the first stage section to the second stage section. A pulse combustion device comprising a pulse combustor coupled to at least one resonance tube, may be placed in communication with the first stage section of the fluid channel. The pulse combustion device may be configured to combust a solid or liquid fuel and create a pulsating combustion stream and an acoustic pressure wave. The fluid channel can be shaped to transmit the acoustic pressure wave from the first stage section to the second stage section.
The system may further include a sulfur capturing agent injection port for injecting a sulfur capturing agent into the second stage section of the fluid channel. The sulfur capturing agent is configured to remove sulfur-containing gases from the pulsating combustion stream and to undergo acoustic agglomeration with any particles contained in the pulsating combustion stream. A particulate removal device, such as a low velocity cyclone in combination with a high velocity cyclone, may receive the combustion stream from the fluid channel. The particulate removal device may be used for removing particulates from the stream. Once the particulates are removed from the stream, the stream may be used in various processes. For example, in one embodiment, the stream may be used to power a gas or steam turbine or may be used to power a fuel cell.
In addition to systems for producing gases, the present invention is also directed to various processes for producing a gas stream having fuel or heat value. In one embodiment, for instance, the process can include the step of combusting a solid or liquid fuel in a pulse combustion device and creating a pulsating combustion stream and an acoustic pressure wave. The pulse combustion device may be operated at sub-stoichiometric conditions. As used herein, sub-stoichiometric conditions refer to combustion conditions in which oxygen is not present in amounts sufficient to completely combust a fuel source. In the present invention, for instance, the pulse combustion device may operate at stoichiometry levels of from about 30% to about 60%. Further, the solid or liquid fuel may be fed to the pulse combustion device in conjunction not only with an oxygen source but also with steam. The steam may be used to control stoichiometry levels, to control temperatures, and to allow for steam reforming.
Once formed, the pulsating combustion stream and the acoustic pressure wave may be directed through a fluid channel. At least one portion of the fluid channel may operate under reducing conditions in order to promote steam gasification. During steam gasification, endothermic reactions occur in which hydrocarbon compounds are broken down and hydrogen is formed. Hydrogen and lower molecular weight hydrocarbon gases are valuable energy sources.
According to the process of the present invention, a sulfur capturing agent may be injected into the fluid channel. The sulfur capturing agent can capture sulfur contained in the pulsating combustion stream. The sulfur capturing agent also acoustically agglomerates with particles contained in the pulsating combustion stream.
From the fluid channel, the combustion stream containing hydrogen and agglomerated particles may then be filtered using any suitable particulate removal device. For example, in one embodiment, dual cyclones may be used to remove the agglomerated particles. The resulting product gas stream may then be used as desired in various processes.
In one embodiment, the agglomerated particles that are removed from the combustion stream may be fed to a heated fluidized bed. The fluidizing medium in the bed may contain oxygen causing exothermic reactions to occur in the bed. For example, in one embodiment, sulfide contained in the agglomerated particles may be converted into a sulfate. In an alternative embodiment, when the sulfur capturing agent is cerium oxide, the agglomerated particles may be placed in the fluidized bed in order to regenerate the cerium oxide and generate sulfur dioxide. The gas stream being created within the fluidized bed may then be treated in order to remove the sulfur dioxide.
In one embodiment, the fluid channel can include a first stage section and a second stage section. The first stage section may be maintained at a temperature of less than about 4000xc2x0 F. and can include a first exit temperature. The second stage section, on the other hand, can include a second exit temperature. The second exit temperature may be less than the first exit temperature and may be no greater than about 1900xc2x0 F., such as less than about 1700xc2x0 F.
Conditions within the first stage section of the fluid channel may be maintained so as to allow for partial oxidation, steam gasification, and slag formation. When slag is formed, the slag may be periodically removed from the fluid channel.
In the second stage section of the fluid channel, however, reducing conditions may exist for promoting steam gasification (also referred to as steam reforming) which promotes the production of hydrogen and other lower molecular weight hydrocarbons.
Other features and aspects of the present invention are described in more detail below.